Wind turbines convert the kinetic energy of the wind into electricity, which is then transmitted to a substation in the wind turbine wind farm. This wind turbine wind farm has at least one wind farm controller and at least one wind turbine comprising a rotor, which drives a generator that interacts with a power converter to generate electricity; a wind turbine controller equipped with a blade pitch angle controller and a generated power controller, a power converter controller, which interacts with the wind turbine controller; and a regulation system that coordinates the different wind turbine controllers on the basis of a series of parameters such as turbine rotation speed or grid frequency.
The nacelle on a wind turbine normally houses different components together with a transmission shaft that converts mechanical energy into electricity through a generator that interacts with a power converter. The transmission shaft in a wind turbine means the assembly between the rotor, rotor shaft, gearbox, generator shaft and generator.
The purpose of the wind turbine controller is to maximize active power generation up to a preset maximum power limit and to maintain a secure operating mode to prevent personal injuries and wind turbine damage. This wind turbine controller defines a blade pitch angle, sent to the pitch actuator to move the blades to the correct position, and an active power reference point as a reference for the converter controller located in the converter control unit.
At present, the impact of connecting wind turbines to the electricity grid is inevitable and thus grid operators are increasingly toughening wind turbine-to-grid coupling conditions. Some of these requirements are defined in terms of frequency transients that wind turbines must be capable of withstanding without uncoupling from the grid and even to react so as to help the system recover the grid frequency to its pre-established nominal values.
Transmission system operators are particularly concerned with frequency transients, normally arising when disconnecting the generator, loads or even a part of the transmission system, and consequently causing the grid frequency to change suddenly beyond its nominal values because of the difference between produced active power and consumed active power. This change in frequency requires a very rapid response to prevent the frequency from surpassing its maximum ranges and provoking a cascading disconnection of generators and electricity consumers.
Generators and grids have different response levels for correcting grid frequency in the event of a sudden drop or surge in frequency. A first and natural response for conventional generators is known as inertial response, which entails the delivery of instantaneous power because of the stored rotational energy in the shafts. A second response comes from a specific controller that increases the generation of power proportionally to the grid frequency deviation with regard to the nominal frequency, a response requiring some 15 to 60 seconds yet arresting the rising/falling frequency. However, this response, known as primary response, does not permit a return to the nominal frequency. The third and fourth responses, known as secondary or tertiary, are based on managing the generation of active power from generators, including the startup of generation units hitherto offline with a view to moving the grid frequency value to the nominal frequency value.
In this regard, insofar as the inertial response, conventional power plants using synchronous machines such as generators are rigidly connected to the grid, thus a change in frequency directly translates into a proportional change in the turbine rotational speed. The mechanical inertia of a synchronous generator thus has an essential role, since this inertia could be viewed as a conversion of a rotating mass's kinetic energy into electricity fed to the grid, whereby helping the grid reduce the frequency drop/spike.
The conversion of kinetic energy into electricity can be expressed in active power generation, i.e., rotational energy is proportional to the square of the turbine's rotational speed, which is proportional to the grid frequency. Given that power is the amount of energy per unit of time, the power delivered, due to the change in frequency, can be expressed by mathematical deduction as negatively proportional to the frequency change rate.
However, variable speed wind turbines do not have this “natural” response (inertial response) to grid frequency changes because electronic converter controllers uncouple the frequency from the generator rotational speed. Therefore, wind turbines do not naturally reduce their speed in relation to the frequency and do not deliver this energy by moving the rotor. Variable speed wind turbines do not buffer frequency drops/spikes.
Given that wind power is becoming an essential part of the electricity system, an incapacity to provide inertial response results in a reduction of the inertia in the system and, consequently, an increase in frequency drops/spikes. Accordingly, measures must be taken to prevent the wind turbines' lack of inertial response, which could entail major problems in the electricity grid caused by frequency drops/spikes.
Wind turbines with inertia control can be useful for smoothing frequency changes and, thus, for restoring the frequency of the system and preventing a drop in the load after a major drop in frequency. For wind turbines, the conceptual approach goes through increasing the active power and feeding it into the electricity grid dynamically and quickly, within a few seconds, using the inertia of the rotating blades. In this regard, various approaches have been addressed by scientific literature and patents.
The paper entitled “Frequency behavior of grid with high penetration rate of wind generation” (J. Duval, B. Meyer; 2009 IEEE Bucharest Power Tech Conference, June 28th-July 2nd, Bucharest, Romania) describes the addition of extra inertia power to the converter reference for the wind turbine controller active power. This additional active power is calculated as proportionally negative to the rate of frequency change with a parameter that defines its proportionality. Nevertheless, the power feed falls quickly thereafter. This drop in the power feed comes from two factors: wind turbine rotor deceleration, which causes a decreased active power reference of the wind turbine controller, and that the wind turbine controller controls the power according to the deviation of the turbine speed compared with a reference speed. As the wind turbine decelerates and deviates from the reference speed, the power must be reduced to recover the reference speed. In grid terms, this is known as a “recovery period” after feeding the inertia, and it entails wind turbine performance uncertainties to the wind farm insofar as frequency response and could even cause an undesired drop in frequency after the inertial response.
Patent WO2011/000531A2 and the paper entitled “Variable Speed Wind Turbines Capability for Temporary Over-Production” (Tarnowski, G. C., Kjar, P. C., Sorensen, P. E., Ostergaard, J. Power & Energy Society General Meeting, 2009. PES '09. IEEE) describe a solution similar to the aforementioned solution, differing only in that the wind turbine controller active power reference sent to the converter is fixed at a preset value for transients during a predefined period matching the expected duration of frequency transients. The additional power is then calculated as negatively proportional to the frequency change rate and proportional to the deviation of the frequency compared to the nominal frequency and added to the set power. In this case, as the controller reference is not followed, there is no drop in power because of wind turbine deceleration. Nevertheless, during the time that overproduction is fed into the grid, the wind turbine decelerates to reach the point of minimum speed, inertia delivery is stopped and the set power value released. This provokes a drastic drop in production, which remains until the wind turbine recovers its initial speed.
Patent WO2011/1124696 is also based on including additional power to the wind turbine controller's active power reference, which can be calculated both proportionally to the deviation of the frequency as well as any other manner. In this case, while the active power speed is not frozen, the wind turbine controller speed is nevertheless adapted, overcoming the issue associated with the drop in power due to wind turbine speed deceleration through the “production of a rotational speed change signal, considering an inertial rotational moment, and taking this as an output signal, which is added to the target rotational speed via a logic element”. In other words, the change in speed as a result of calculating this additional power, considering the rotational inertial moment, is entered into the wind turbine controller to change the reference speed and thus prevent the drop in active power reference. However, when this extra power ends, the wind turbine should return to its normal operating mode, resulting in the ensuing “recovery period”, which could cause an undesired frequency drop after this inertial response.
A conclusion could be drawn based on the state of the art that there is always a “recovery period”, which depends on the performance of the wind turbine before this period commences. This “recovery period” is a challenge facing the grid because, during the delivery of the inertial response, the grid is supported and the grid frequency change is buffered; thus the wind farm is helping the system through this situation. Nevertheless, when the recovery period commences, wind farm production drops below the values before the event and, consequently, during this period of time, the wind farm could cause a grid frequency drop that must be solved by another generation plant.